After an oil or gas well is drilled within an underground hydrocarbon formation, the zones of interest need to be completed prior to production commencing. Part of the completion process typically includes a fracking operation which involves injection of high pressure fluids into the reservoir to initiate fractures within the surrounding rock to increase porosity of “tight” formations and thereby increase the ability of hydrocarbons within the formation to flow into the wellbore and thereafter be pumped to surface.
Fracking operations for completing a well within a reservoir may increase production from the well by many multiples in a given time period, in some cases up to 3× or greater if conducted over the entire length of a horizontal wellbore than what would otherwise have been the case if a fracking operation had not been completed.
Accordingly, the fracking process can be a very important and critical step in preparing a wellbore for production. It is important, however, to be able to frack and complete a wellbore and ready it for production as quickly and efficiently as possible since delay further increases the expense of providing equipment such as tanker trucks for transporting frac fluid to site and remaining “on site” while frac fluid is drawn from such trucks and injected downhole, as such frac trucks typically charge at an hourly rate, to say nothing of the revenue lost arising from the delay in the well coming “on line”.
In the stimulation/fracking of directional and horizontal wells, it can be desirable to treat multiple stages in a single zone, known as a cluster, with a single fracture stimulation. It can also be desirable to treat more than one zone with a single fracture stimulation to save time and expense associated with multiple treatments and time spent running tubing and tools in and out of the wellbore.
Various prior art downhole tools and systems exist and have been used to stimulate wells by permitting treatment/fracturing in multiple contiguous regions within a single zone.
Many of such tools and systems require complex valving components within a wellbore to selectively/successively open certain ports for fracking, and thereafter open and frac at all ports along the wellbore. As a result, to the extent such systems or remnants thereof remain in the wellbore when production commences, such disadvantageously restrict flow of hydrocarbons through and thus production of hydrocarbons from, the wellbore.
Also disadvantageously, such prior art systems, to the extent that remnants of the valving remain in the wellbore when production commences, such accordingly reduce the diameter of a downhole pump which may be inserted in the wellbore when the well goes “on line” and thus require the use of smaller diameter pumps which thereby undesirably limit the rate at which hydrocarbons, typically oil, can be produced from the well.
As well, due to complex configuration and multiplicity of mechanisms to open frac ports, numerous flow restrictions exist within tubing and thus numerous pressure drops are caused occur along the length of the tubing, which result in less efficient fracking as there is greater pressure loss incurred prior to the fracture fluid contacting the zone. Ideally, less pressure drop is desired to conduct a fracture stimulation more efficiently in each stage, to avoid having to use oversize frac injection pumps.
To avoid the aforesaid problems, resort is often had to milling out of some or all of the frac port opening/closing components prior to being able to commence production flow from the hydrocarbon bearing zones. These processes are not only expensive, but time consuming as well.
It is thus desirous to have fewer or no materials/components to mill out within the bore liner, in order to be able to immediately after fracking be able to commence production from the hydrocarbon bearing zones.
Numerous patents and pending patent applications exist related to apparatus and systems for opening a plurality of ports in a liner within a wellbore at multiple contiguous locations therealong, to thereby permit injection of a fluid from such liner into a hydrocarbon formation, for the purpose of fracturing the formation and conditioning the formation at such locations.
For example, U.S. Pat. No. 8,215,411 teaches a plurality of opening sleeve/cluster valves along a liner for wellbore treatment, and utilizes a ball member or plug to open a sleeve at each valve thereby allowing fluid communication between the bore and a port in the sleeve's housing. This invention requires, however, a ball seat corresponding to each sleeve in a cluster valve, potentially restricting flow. The presence of a ball seat at each valve to be opened, due to the resulting bore restriction at each valve sleeve, creates a significant pressure drop across the cluster valve assembly.
U.S. Pat. No. 8,395,879 teaches a hydrostatically powered sliding sleeve. Again, such configuration utilizes a single ball, but each sliding sleeve configuration requires its own ball seat, and the balls need to later be pumped out.
U.S. Pat. No. 4,893,678 discloses a multiple-set downhole tool and method that utilizes a single ball. Again, each valve requires a seat which is integral with a sliding sleeve, and which remains with each valve/port. When the sleeve/seat is forced by the ball to slide and thereby open the port, collet fingers may then move radially outwardly, disengaging the ball and allowing the ball to further travel downhole to actuate (open) further ports.
US Patent Application Publication No. 2014/0102709 discloses a tool and method for fracturing a wellbore that uses a single ball, each valve with a deformable ball seat. Again, each valve has a valve seat which remains with each valve/port.
Other patents and published applications avoid the problem of each valve/port having a ball seat which remains with each valve, and provide a dart or ball member which actuates a number of valves/ports. However, such designs are not without their own unique drawbacks.
For example, US 2013/0068484 published Mar. 21, 2013, inter alia in FIG. 6 thereof, (and likewise to same effect US 2004/0118564 published Jun. 24, 2004, likewise in FIG. 6 thereof) teaches an axially movable sliding sleeve 322 which is capable of actuating (i.e. opening) a number of downhole port sleeves 325a, 325b to thereby open corresponding respective downhole ports 317a, 317a′ which are normally covered by port sleeve 325a, and similarly subsequently open respective downhole ports 317b, 317b′ normally covered by port sleeve 325b. Sliding sleeve 322 is mounted by a shear pin 350 in the tubing string. Plug/ball 324 is inserted in the tubing, and uphole fluid pressure applied thereto cause plug 324 to travel downwardly in the in the string and abut sliding sleeve 322, further causing shear pin 350 to shear and thus sleeve 322 to then be driven downhole. Spring-biased dogs 351 on outer periphery of sliding sleeve 322 then engage inner profile 353a on sliding sleeve 325a and cause sleeve 325a (due to fluid pressure acting on plug 324) to move downhole thereby opening ports 317a, 317a′. As noted in paragraph [0071] therein, continued application of fluid pressure causes dogs 351 to collapse, thereby releasing sleeve 322 from engagement with inner profile 353a on sliding sleeve 325, and allowing sleeve 322 to further travel downhole and actuate (i.e. open) further sleeves in like manner. Although not expressly mentioned nor shown in US 2013/0068484, seals are necessary around dogs 351 in order to allow creation of a pressure differential when such continued application of fluid pressure is applied, in order to cause collapse of such dogs to allow disengagement with a first sleeve and allow the dart to thereafter further travel downhole for subsequent actuation of additional downhole sleeves and ports. The necessity for seals around dogs 351 necessarily introduces added mechanical complexity and the possibility of inability to release sleeve 322 from engagement if such seals were to leak due to the then-inability to create a pressure differential.
WO 2013/048810 entitled “Multizone Treatment System” published Apr. 4, 2013 teaches a system and method for successively opening flow control devises (which may be sliding sleeves) in a tubing string along a length thereof, commencing with a most downhole valve and opening a sleeve at such location, and by insertion of additional darts progressing successively upwardly in the tubing string to open further uphole sleeves. The tubing string is provided with a plurality of spaced apart flow control devices, such as sliding sleeves, each having an annulary-located recess therein with a unique profile relative to other flow control devices. A first dart, having an engagement feature sized to correspond with a selected annulary-located recess of a particular most-downhole flow control device, is injected, and such dart passes to actuate the flow control device to allow it to open a port. The process is progressively repeated for additional uphole flow control devices by injecting additional darts, having corresponding features to engage a selected flow control device. The darts are then drilled out to allow production from the tubing. Disadvantageously, only one dart can open one port, and thus a plurality of contiguously spaced ports are not capable of being opened by a single dart using such apparatus/method, thereby rendering such system/method time consuming.
CA 2,842,568 entitled “Apparatus and Method for Perforating a Wellbore Casing, and Method and Apparatus for Fracturing a Formation” published May 29, 2014 teaches inter alia dart members similar to the dart of WO 2013/048810, each dart having a protruding spring-biased profile uniquely sized to engage a similarly-sized annular recess on a plurality of downhole sliding sleeves, and thereby open sliding sleeve, with further means being provided on each of such sliding sleeves to allow the single dart member to further travel downhole and open additional sleeves having similar-sized annular recesses. No collet sleeve is provided, and a non-beveled surface on the annular recess of the most downhole sleeve is used to retain the dart from travelling further downhole. Disadvantageously, in comparison to the system as hereinafter described, the configuration of the dart, namely having a spring-biased profile and a cup seal thereon, essentially requires the dart to be virtually solid and thereby permanent obstruction to the wellbore once opening the last of a series of slidable sleeves. If additional uphole sleeves are desired to be actuated using a second dart (having a narrower protruding spring-biased profile than the first dart used), the first dart must be installed using a locator tool and thereafter retrieved, after actuating a plurality of sleeves and associated ports using such tool, as shown in FIGS. 9A-9D. Such a system involves extensive equipment from surface, and the need of a bypass port that need by opened and closed to allow effective operation. These steps and features complicate the operation of such prior art system and add to expense and time.
US Pub. 2016-0097257 (CA 2,867, 207) filed Oct. 2, 2014 entitled “Multi-Stage Liner with Cluster Valves and Method of Use”, commonly assigned with the present application, teaches a method and system of flowing a ball and ball seat member downhole, which successively engages and disengages a plurality (cluster) of sliding sleeve members, to thereby successively open frac ports. The sliding sleeve members are initially respectively covering a plurality of longitudinally-spaced frac ports along a tubular liner in a wellbore. The ball and seat member is flowed downhole by application of fluid pressure on an uphole side thereof. The ball and seat member initially engages a sliding sleeve member covering a most uphole frac port, and causes the sliding sleeve member to slide so as to uncover the associated frac port, whereupon the ball and seat member upon continued application of uphole fluid pressure becomes disengaged, and thereafter moves downhole to successively engage and uncover frac ports in a cluster of sliding sleeve members.
US Pub. 2016-0097257 (CA 2,879,044) filed Jan. 22, 2015 entitled “System and Method for Injecting Fluid at Selected Locations along a Wellbore”, likewise commonly assigned with the present application, teaches a system and method for selectively actuating sliding sleeves to uncover associated frac ports in a tubular member, using one or more actuating dart members. The dart member may thereafter be coupled to a retrieval tool and when so coupled allows a bypass valve to be opened and disengagement of the dart member from the associated sleeve to allow withdrawing the dart member uphole and from within the tubular member. Specifically, upward movement of the retrieval tool allows a wedge-shaped member on the dart member to disengage the dart member from a corresponding actuated sliding sleeve, to thereby allow the dart member to be withdrawn from the wellbore.
US Pub. 2016-0312580 (CA 2,904,470) filed Apr. 27, 2015 entitled “System for Successively Uncovering Ports along a Wellbore to permit Injection of a Fluid along said Wellbore” having a common inventor and likewise commonly assigned with the present application, teaches a system for moving sleeves to successively uncover a plurality of contiguous ports in a tubing liner within a wellbore which are covered by such sleeves, or for successively uncovering individual groups of ports arranged at different locations along the liner, to allow successive fracking of the wellbore at such locations. Sliding sleeves in the tubing liner are successively moved from a closed position covering a respective port to an open position uncovering such port by an actuation member placed in the bore of the tubing liner and pumped down the tubing liner. The actuation member for moving the sliding sleeves to cause them to open comprises a single collet sleeve, having a dissolvable plug retained in a fixed position within such collet sleeve by shear pins. The collet sleeve has radially-outwardly biased protuberances (fingers) at a downhole end thereof, adapted to and which matingly engage corresponding cylindrical grooves in such sliding sleeves, based on the width of the protuberance. Upon the actuation member actuating all of the desired sleeves and after having actuated the last most downhole sleeve, the shear pin shears thereby allowing the plug in the collet to move downhole in the collet sleeve and thereby prevent the protuberances (fingers) on the collet sleeve from thereafter disengaging the cylindrical groove of the corresponding sliding sleeve, thereby preventing any further progress of the collet sleeve downhole.
U.S. Ser. No. 14/991,597 (CA 2,916,982) filed Jan. 8, 2017 entitled “Collet Baffle System and Method for Fracking a Hydrocarbon Formation”, likewise commonly assigned with the present application, teaches a baffle system for progressively fracking or treating a formation via a plurality of longitudinally spaced frac ports along a tubular liner. The baffle members each have a collet finger protuberance thereon of a unique width relative to other baffle members. Each collet finger protuberance on an uphole edge thereof has a chamfer which allows disengagement of the collet finger protuberance and thus removal of the baffle member from the wellbore when the baffle member is pulled uphole by a wireline retrieval tool.
None of the aforesaid patents/publications, however, teach or in any way suggest how such systems or methods could be further adapted to provide not only fracking, but further provide sand control during production without having to trip out the frac string from the wellbore.
Fracking fluid is usually an incompressible liquid for the purpose of fracturing the rock, and may contain various adjuvants such as acids and/or diluents to increase followability of the oil/gas from the formation.
In addition, fracking fluids commonly contain proppants such as fine sand (frac sand) or ceramic beads of consistent and engineered uniform diameter, to uniformly “prop” open the created fractures and maintain such fractures in the formation so that hydrocarbons may better flow from the formation.
As explained below, the introduction of large quantities of frac sand into a formation during the fracking process typically results in significant quantities of frac sand being entrained in the oil or gas which flows back into the wellbore for pumping to surface. Due to the abrasive nature of sand, such results in additional increased and heavy wear on pump components within the well, greatly shortening pump life. Downhole pumps, and even downhole pumps most resistive to sand abrasion such as progressive cavity pumps, are typically expensive, and frequent replacement thereof results in increased costs not only in replacing/refurbishing the pump and its components, but further results in service rig time and costs in having to “trip out” of a well a downhole pump and “run back in” the production string with a new pump, to say nothing of the lost production and profits due to the well being “off line” during the time of such repairs.
Sand screens are known in the art, and are typically inserted within a production string, after the tripping out of the frac string from the well. The production string is then separately “run in” wellbore.
Disadvantageously, however, the aforesaid two-step process having to frac, trip out the frac string, and then run in a production string with pre-installed sand screens thereon results in considerable additional time and expense in tripping out the frac string, and thereafter running in the production string with elongate cylindrical screens installed thereon. There is also an inherent risk of damaging the screens during “run in” of the production string in the wellbore.
A more efficient system which allows not only fracking, but further immediately thereafter allows production and sand control during such production, without having to trip out a frac string, would be very beneficial to the wellbore completion industry.
The above-background information and description of prior publications is provided for the purpose of making known information believed by the applicant to be of possible relevance to the present invention. No admission is necessarily intended nor should be construed, that any of the below publications and information provided below constitutes prior art against the present invention.